Surfactant method for improved oil recovery from fractured reservoirs

ABSTRACT

A method to enhance oil recovery from a fractured carbonate reservoir, the reservoir being accessible via a production well. The method includes injecting a surfactant solution including surfactants into the production well, and injecting a second well treatment process into the production well. The second well treatment process includes a second well treatment solution. The second well treatment solution is selected from the group consisting of a scale inhibition squeeze process, a well acidizing process, a chemical process to reduce water production rate, carbon dioxide injection for stimulation of a production or injection well, an acid fracturing process, and a hydraulic fracturing process. The surfactant solution and the second well treatment solution are injected into the production well within less than about six months from one another.

This application claims the benefit of U.S. Provisional Application No.60/782,263, filed Mar. 15, 2006, which is hereby incorporated byreference herein in its entirety.

FIELD

The disclosures herein relate to the field of crude oil production, andparticularly to methods to increase the recovery of crude oil fromfractured carbonate subsurface reservoirs.

BACKGROUND

Many reservoirs from which oil and gas are produced are not homogeneousin the geologic properties (e.g. porosity and permeability). In fact,many of such reservoirs, especially those consisting of carbonate typeof rocks (e.g. limestone and dolomite) are naturally and significantlyfractured. Typical examples of such reservoirs are those in theSpraberry trend in West Texas. In addition, often in carbonatereservoirs the rock matrix is fractured deliberately by well treatmentsin order to increase the flow of fluids near the well bore region.

Fractured reservoirs consist of two distinct elements: fractures andmatrix. The fracture system is a series of interconnected cracks thatcan transmit fluids easily (very high permeability), but make up only asmall fraction of the total porosity. The matrix portion consists of theoil-bearing porous rock that typically has much lower permeability andhas the bulk of the total porosity of the reservoir. Hydrocarbonproduction is normally less efficient in fractured reservoirs. Duringprimary production the natural reservoir pressures to produce the oil inplace will quickly decrease and more than 90% of the original oil instill left in place. Similarly, conventional methods of secondaryrecovery fail to displace substantial volumes of “left-in-place” oil.

Conventional waterflooding techniques have relatively low efficiency inhighly fractured reservoirs. Waterflooding in these reservoirs ischaracterized by early water breakthrough and rapidly increasingwater-oil ratios to an uneconomic level. The injected water tends totravel only through the fractures and not interact with the rock matrix.That is, the water cannot penetrate into the matrix and thereby displaceand recover oil trapped in the porous matrix. This injected water tendsto recover only the oil left behind in the fracture system followingprimary production. This limited or no interaction of the water with thematrix is caused in large part by the matrix portion not beingwater-wet. That is, the matrix will not spontaneously imbibe water.

One approach to increase the penetration of a water phase with thematrix blocks containing trapped oil is to add a surfactant to thewater. Previous research and field experience has demonstrated thatincluding a low concentration of the properly selected surfactant to thewater will reduce the interfacial tension and also create now awater-wet condition in the area near the fracture face. With thisaltered condition, the aqueous phase then penetrates some distance intothe porous matrix and thereby pushes out some of the oil that was withinthe pore spaces. In this countercurrent imbibition process the oil thatis displaced from the matrix then moves into the fracture system. Oncepushed into the fracture system, this oil can be moved easily to aproduction well. In a countercurrent imbibition process, with or withoutthe addition of a water-wetting surfactant, the rate of oil recovery isdependent upon the capillary pressure characteristics of the porous rockmatrix. That is, the imbibition process is essentially unaffected byconventional techniques for controlling field operations, such asselecting pressures and flow rates.

“Surface Chemistry of Oil Recovery from Fractured, Oil-Wet CarbonateFormations” (G. Hirasaki and D. L. Zhang, (2000)) describes an oilrecovery process employing water-imbibition displacement in naturallyfractured carbonate reservoirs. U.S. Pat. No. 4,364,431 to Saidi et alutilizes a surfactant to augment a waterflood which displaces oil from afractured formation, by a gravity drive mechanism rather than animbibition displaced mechanism. Saidi suggests that the surfactantreduces the interfacial tension between the water in the factures andthe oil in the matrix blocks of the formation, which enables the oil toenter the factures where it is driven upward to a producing well by thedensity difference between water and oil.

Waterflood recovery by countercurrent imbibition may be further improvedby the use of surface active agents which reduce interfacial surfacetension between the oil and water phase, as disclosed in U.S. Pat. No.2,792,894 by Graham. Examples included the improved imbibition into aporous rock by an aqueous phase that includes a surfactant. This processis advantageous for fractured reservoirs where there is a markedcapillary pressure difference between the fluids in the fracture systemand the porous rock formation.

U.S. Pat. No. 4,842,065 by McClure discloses that alternating surfactantslugs and water can improve oil recovery in fractured formations. Thesurfactant solution causes it to be the preferred wetting phase of thematrix blocks into the fracture network. The formation is then floodedwith water from an injection well to displace the oil from the fracturenetwork to the surface via a production well while returning the matrixblocks in the reservoir to a less water-wet condition. The injectioncycle is repeated until the formation is depleted.

Austad and Standes in “Spontaneous Imbibition of Water into Oil-WetCarbonates”, Journal of Petroleum Science and Engineering, 2003, vol 39,pp. 363-376, describes laboratory experiments in which aqueoussurfactant solutions recover oil from carbonate cores. These authorspresent data for a number of cationic and anionic surfactants, that whendissolved as a dilute solution in water, will imbibe spontaneously intocarbonate cores containing a crude oil, and thereby recover some of thiscrude oil. H L Chen et al. present in paper SPE 59006 results forsimilar laboratory experiments in which aqueous solutions of nonionicsurfactants imbibe into and thereby recover from carbonate cores oilformerly trapped inside the porous core. Hirasaki and Zhang demonstratethat anionic surfactants in an aqueous solution also containing sodiumcarbonate to increase the solution pH and adjust the salinity can imbibeinto carbonate cores that contain initially a high saturation of a crudeoil.

One method in particular to apply aqueous surfactant solutions toincrease the oil recovery from fractured reservoirs is to treatindividual production wells with a stimulation fluid that comprises afresh water or brine with a suitable surfactant added. A “suitablesurfactant” is a surfactant that will dissolve in the injection brine,be compatible with the reservoir brine, plus its solution has thedesired behavior to penetrate spontaneously into a porous matrix. Theinjection-production method described below may be called a “huff-puff”,“surfactant soak”, or “surfactant squeeze” treatment. First, aproduction well halts production of fluids. Next a brine/surfactantsolution is injected into the production well. This forces the treatmentfluid into the fracture system some distance from the wellbore and intothe reservoir. This is followed by an optional flush fluid to drive thesurfactant deeper into the reservoir. The well may be shut-in for aperiod of time (typically from a few hours to a few days) to allow thesurfactant solution to soak better into the matrix and displace some ofthe trapped oil in the matrix into the fracture system. Finally, thewell is placed back on production and the extra oil forced into thefractures comes back to the production well and is produced. Thisprocess can increase the oil production for some period of time when thewell is placed back on production. This oilfield application method isdescribed, and is observed to recover additional oil, for example, inthe HL Chen paper SPE (Society of Petroleum Engineers) 59006 and thepaper by W. W. Weiss (“Artificial Intelligence Used to Evaluate 23Single-Well Surfactant Soak Treatments”, SPE Reservoir Evaluation &Engineering, June 2006).

The June 2006 paper by Weiss includes a discussion about the surfactantoil recovery results being worse than expected when there is an acidtreatment that is performed before the application of the surfactant. Itis speculated that the acid reacting first on the rock surfaces impedesthe penetration of the surfactant that contacts those same acid-treatedsurfaces later. Thus combined application of the surfactant soak and asecond process can produce a negative result. (It is noted that the June2006 paper by Weiss et al. is dated after the priority date of thisapplication, and so does not constitute “background” art, but is merelyincluded to demonstrate an important point, and that is that other welltreatments, when followed by a surfactant injection, can producenegative results over surfactant treatment alone.)

U.S. Pat. No. 5,247,993 to Sarem et al. describes an improvementwherein, if while performing a surfactant soak process in a fracturedreservoir, that the fluid in the flush step (i.e., the fluid just afterthe surfactant slug) can increase the oil-mobility and decrease thewater-mobility. Examples cited therein include using steam orhydrocarbon, or adding a thickening agent to the water flush.

A need therefore exists for processes that improve on the oil productionand economic results of surfactant solution injection-productionprocesses in oil reservoirs.

SUMMARY

At least one embodiment disclosed herein provides for a method toenhance oil recovery from a fractured carbonate reservoir, the reservoirbeing accessible via a production well. The method comprises injecting asurfactant solution comprising surfactants into the production well, andwherein the surfactant solution selected to recover additional oil froma porous matrix portion of the reservoir. The method also provides forinjecting a second well treatment process into the production well, andwherein the second well treatment process including a second welltreatment solution. The second well treatment solution is selected fromthe group consisting of a scale inhibition squeeze process, a wellacidizing process, a chemical process to reduce water production rate,the injection of carbon dioxide as a stimulation fluid at either aproduction or injection wells, an acid fracturing process, and ahydraulic fracturing process. The surfactant solution and the secondwell treatment solution are injected into the production well withinless than about six months from one another.

DETAILED DESCRIPTION

In one embodiment, a process is described to combine surfactant enhancedoil recovery (“EOR”) “huff-puff” operation with other common oil fieldtreatments performed in production wells in fractured reservoirs. These“other common oil field treatments” can include, but are not limited to,scale inhibitor squeeze, acid stimulation, other stimulation fluids(e.g. organic solvents to remove wax/asphaltenes), injecting polymergels or other fluids to reduce the production rate of water, injectingcarbon dioxide to stimulate oil production at either a production or aninjection well, and injecting fluids for purposes of inducing cracks toimprove fluid production flow (commonly called “hydraulic fracturing”).(When this last process includes injection steps with an acid solution,this treatment is referred to as “acid-fracturing”.)

Using a combination of a surfactant EOR treatment and another productionwell treatment operation is a better strategy than using surfactant EORtreatment alone because: (a) it is more cost-efficient in terms oflogistics to perform more than one well treatment process immediatelyone after the other (in this way equipment and labor are mobilized oncefor a combined operation rather than at two separate times); (b) whenthe surfactant soak treatment slug is injected first, then before orduring the time while the EOR surfactant is soaking during an optionalwell shut-in period, preparations may be made for the other portions ofthe second well treatment program: when the second treatment fluid isinjected first, then while that process is underway, on-sitepreparations may be made for the surfactant EOR treatment program; and(c) the chemicals involved in the other, second well treatment processcan provide synergistic oil recovery performance when they mix with theEOR surfactant in-situ. That is, the oil recovery from the reservoirwill be greater with the mixture of chemicals than with the sum of theiroil recovery if practiced individually. This surprising result iscontrary to results previously known (as discussed above), and offersadditional opportunity to increase oil production from subterranean oilreservoirs.

In accordance another embodiment described herein, as an alternativeprocess, in some cases the EOR surfactant can be combined intimatelywith the other treatment process fluid chemical to create a new blend ofchemicals as a single treatment fluid. Having a single, combinedfunction fluid can be advantageous in terms of: (a) simplifying thelogistics and reducing the operational costs to apply effectively twowell treatment effects simultaneously; and (b) taking advantage ofpotential synergistic performance between the combined chemicalsolutions. That is, a properly designed blended system can produce moreoil than otherwise due to the surfactant action, plus have the same oreven better intended result for the objective of the other chemicaltreatment system (e.g. accomplish more complete removal of formationdamage, have better performance of scale-preventing chemical, etc.).

As indicated above, in one embodiment a surfactant EOR “huff-puff”operation is combined with another common oil field treatment ortreatments performed in production wells in carbonate reservoirs tocreate a synergistic beneficial increase in oil recovery. The examplesprovided below illustrate how a mixture of the surfactant solution andthe chemicals in the second treatment can produce a surprisingly greateroil recovery than otherwise would be expected. One reason that theadvantageous results of the embodiments described herein is unexpectedis that while the surfactant treatment is intended solely for theincrease in oil recovery by its chemical action on the reservoir rock,the second treatment (or treatments) are not intended for more oilrecovery per se, but are typically intended to reduce or removeimpediments to total fluid production rate. So when properly designed,the combined process will produce more oil than by the surfactantprocess alone, plus the main function of the second treatment to removeor prevent flow restrictions, or increase fluid flow paths, will also beaccomplished successfully.

Such combined treatments also have the advantage of reducing thelogistic efforts and costs by conducting the two treatments in concertrather than as individual processes performed at separate times. These“other common oil field treatments” that can be combined with asurfactant EOR “huff-puff” operation include, but are not limited to,scale inhibitor squeeze, acid stimulation, other stimulation fluids(e.g. chemical fluids to remove inorganic, water-borne deposits ororganic deposits such as wax or asphaltenes, injecting polymer-gels orother fluids for the purpose of reducing the rate of produced water,injecting carbon dioxide to stimulate the reservoir either at aproduction or injection well, and injecting fluids for purposes ofinducing fractures to improve fluid production), and placing chemicalsor materials near a production wellbore for purposes of reducing therate of water production.

As indicated, none of the references cited consider, or they fail toimplement successfully, the process improvements that lead to thesurprising beneficial results described below when combining thesurfactant solution EOP process in fractured carbonate reservoirs withother production well treatments performed for other purposes (e.g.,removing plugging deposits, adding scale prevention chemical, reducingwater production rate, or inducing additional fractures to increase easeof total fluid production).

It is recognized in the processes claimed herein that the details of itsdesign need to be considered to have a successful further benefit to theamount of oil recovered when combining the surfactant treatment withsecondary oil well treatments. For example, Example 4 (provided below)demonstrates that adding a proper surfactant with an acid as an intimatesolution will provide a synergistic benefit to oil recovery. Thiscombined process takes advantage of the physics of each process to worktogether better and hence recover more oil than otherwise possible bythe sum of their oil recovery if applied as distinct individualprocesses.

As discussed above, highly fractured reservoirs consist of two distinctelements: fractures and matrix. The fracture system is a series ofinterconnected cracks that can transmit fluids easily (very highpermeability), but makes up only a small fraction of the total porosityof the reservoir. The matrix portion consists of the oil-bearing porousrock that typically has much lower permeability but has the bulk of thetotal porosity of the reservoir. In the case where a hydraulic fractureor acid fracture treatment is performed, fractures are present at leastdue in part to a man-made activity. The process claimed herein isapplicable to natural, as well as man-made (and combinations thereof)fracture systems in oil reservoirs.

The processes described herein are particularly applicable to formationshaving matrix blocks where an ordinary water-phase does not have atendency to imbibe spontaneously into such a rock matrix. Suchformations contain matrix blocks with most, if not all, of the rocksurface is not water-wet.

While the processes described herein are not limited to formations of agiven temperature, the processes are particularly useful in formationshaving a relatively lower ambient temperature. Thus the processesdescribed herein are particularly applicable to formations having anambient temperature range from about 20 C to 90 C, and more particularlyfrom about 20 C to about 70 C.

The processes described herein are not limited by the salinity of theformation brine, or with the salinity of the make-up water for thesurfactant treatment. However, the surfactant to be injected is selectedto be compatible with the water in which it is dissolved, the brine inthe formation, or when mixed with other treatment solutions. The word“compatible” in this instance means that the surfactant will dissolveessentially completely into the subject solution and result in noobvious precipitate forming after standing for at least 24 hours. Thoseskilled in the art can select surfactants that will fulfill thesecriteria. While not a limiting factor, advantageously the processesdescribed herein are conducted in the presence of brine salinities ofless than about 250,000 mg/l total dissolved solids, and moreadvantageously when the salinity is less than about 150,000 mg/l totaldissolved solids.

One embodiment of the processes described herein comprises firstapplying a surfactant EOR treatment to an oil reservoir by injecting asurfactant into the reservoir, and subsequently applying a second welltreatment process to the reservoir. The steps involved in performingthis combined operation are as follows:

-   -   Cease production at an production well;    -   Inject a surfactant EOR solution (and an optional flush) into        the production well;    -   Optionally, halting injection of the surfactant EOR solution and        allowing a soak period. (Soaking can increase the surfactant        solution penetration into the matrix system of the production        well);    -   During (or before) the (optional) soak period, prepare surface        operation for performing a second fluid treatment program        comprising a second treatment fluid;    -   Inject the second treatment fluid into the production well to        accomplish its primary intended purpose (e.g., remove scale,        fracture, etc.);    -   Optionally inject a spacer slug of inert fluid into the        production well; and    -   Place the well back on production.

As a result, more oil will be produced than if the surfactant EORtreatment is performed alone.

After the oil production rate declines substantially, the above stepscan be repeated to again cause an increase in oil rate at the subjectproduction well.

In another embodiment, a common well treatment fluid is first injectedinto an oil reservoir via a production well, followed with injecting asurfactant EOR treatment solution into the production well. The generalprocedure for this combination of treatments is as follows:

-   -   Cease production at an production well;    -   Inject common well treatment fluid into the production well to        at least accomplish its intended purpose;    -   Optionally, inject a spacer slug of inert fluid into the        production well;    -   Inject the surfactant EOR treatment solution into the production        well;    -   Optionally, inject another spacer slug of inert fluid into the        production well;    -   Optionally, halt injection and provide a soak period to allow        the surfactant solution to penetrate into the matrix system; and    -   Place the well back on production.

As a result, more oil will be produced than if the surfactant EORtreatment is performed alone.

After the oil production rate declines substantially, the above stepscan be repeated to again cause an increase in oil rate at the subjectproduction well.

A surfactant solution is selected for use in the present embodimentshaving a characteristic which is capable of altering the wettability ofthe matrix rock to be more water-wet.

The wettability-altering agent is a composition from a class ofcompounds commonly known as surfactants. Surfactants generally have ahydrophilic and a lipophilic character which varies as a function of thesurfactant composition as well as the nature of the formation rock andconnate fluids which the surfactant contacts.

The embodiments described herein are not limited to any particularsurfactant, so long as the surfactant satisfies the above statedcriteria. Nevertheless, a preferred surfactant for use in the presentinvention is one which achieves a substantially neutral balance betweenits hydrophilic and lipophilic character within the given formation inwhich the surfactant is placed. Exemplary types of anionic and nonionicsurfactants or their mixtures which have particular utility in thepresent embodiments include ethoxylated alkylphenols, ethoxysulfatealkylphenols, ethoxylated alcohols, ethoxysulfate alcohols, alpha olefinsulfonates, internal olefin sulfonates, alkyl aryl sulfonates, petroleumsulfonates, propoxylated ethoxylated alcohols, propoxylated ethoxylatedsulfates, and propoxylated ethoxylated sulfonates. Another class ofsurface active agents which are advantageously useful in carrying outthe methods described herein are amine salts, ammonium salts, and othersof a similar type of cationic surfactants, either alone or mixed withother types of surfactants. Exemplary of these compounds include primaryamines; some commercial cationic surfactants (examples include ArquadT-50 (Trimethyl tallowalkyl (C₁₆-C₁₈) ammonium chloride) and Arquad C-50(Coconut oil alkyl (C₁₂-C₁₄) trimethylammonium chloride, available fromAkzo Nobel). The surfactants can be manufactured by synthetic means, orvia biosynthesis. Exemplary of the biosurfactants include, but are notlimited to, rhamnolipd or surfactin types.

The surfactant solution can be prepared by mixing the selectedsurfactant in a diluent. The concentration of the surfactant in thediluent is desirably greater than about 0.01% by weight. The surfactantconcentration is desirably between about 0.1% and 4.0% by weight. Theconcentration is most desirably between about 0.1% and about 1.0% byweight. Brine generally has a total dissolved solids concentration above1000 ppm while fresh water has a total dissolved solids concentrationbelow about 1000 ppm.

The volume of the initial surfactant solution slug which is injectedinto the formation depends on which one of several embodimentsencompassed within the present disclosure is being practiced. A numberof variations in the processes disclosed herein can be used, dependingon which well treatment processes are employed and the specific sequencein which they are employed. Generally, a useful surfactant treatmentvolume is between 100 and 50,000 barrels (each barrel contains 42gallons). The surfactant volume solution volume is most desirablybetween about 500 and about 10,000 barrels.

The surfactant slug injected into the reservoir can be preceded by (orfollowed by) a spacer slug volume of a fluid such as a non-damaging,inert brine (e.g. 3 wt % potassium or ammonium chloride). If the spacerslug is employed, a typical size of the spacer slug is at least thevolume of the wellbore; the spacer slug can be a larger volume if itpreferred to minimize the interaction in-situ between the fluid in thefirst process, the surfactant EOR treatment, and the fluids and chemicalfrom the second process. If instead there is a preference to encouragemixing of the fluids in-situ to take advantage of a synergistic effect,then the spacer slug is not used, or its volume is kept small.

After the surfactant and optional spacer slug injection steps arecompleted the well can be shut-in for some period of time to allow thesurfactant solution to imbibe into the matrix rock and thereby displacea significant volume of oil into the fracture system. The shut-in timeis optional, and if included, can be from a few hours to 100 days ormore. Typically, the shut-in time period, if employed, is from betweenabout 2 to 10 days.

The second, “other” well treatment process is implemented either justafter, or just before, the surfactant EOR treatment process (subject toinclusion of a spacer slug, as indicated above). Preferably (but by nomeans exclusively), the second well treatment program is performed afterthe surfactant EOR fluid soak period. The second well treatment processcan be carried out with the same chemical design and injectionprocedures as has been conducted previously in production wells infractured carbonate formations that have not ever employed a surfactantEOR treatment.

In a third embodiment, the surfactant EOR chemical is combinedintimately with the fluids used in the other, second type of welltreatment process. This modified chemical mixture can be used to recovermore oil than otherwise would result from individual treatment using thetwo treatments separately because the surfactant included in the mixtureprovides an enhanced wetting condition for the porous matrix in the areaof the fractures. The other intended purpose(s) of the second combinedtreatment fluid remain the same (e.g. apply a scale inhibitor, removeformation damage, reduce water production, create more fractures, etc.).In light of the above disclosure, those skilled in the art willunderstand how to create such a combined chemical solution that willinclude a suitable surfactant for altering the wettability of thecontacted matrix portion, plus still perform the other intendedtreatment function, and in addition, create an initially formulatedsystem wherein all of the chemical components are compatible with oneanother. Advantages to having a single combined treatment fluid include:(1) the time required to perform both treatment functions is shorter;(2) the logistics of implementing the process in the field is simplerthan performing the surfactant EOR treatment followed by a differentwell treatment process; (3) there are synergistic benefits in improvingthe oil recovery performance of the surfactant EOR system than if it isimplemented by itself, and (4) there can be the same or even betteroutcome for the second treatment function than otherwise if implementedby itself.

EXAMPLES Example 1

Combining a scale inhibitor treatment with a surfactant EOR processresults in a surprising, unexpected further increase in the oilrecovery. That is, this process recovers more oil than would otherwisebe recovered by the surfactant EOR process alone, since the scaleinhibitor by itself has no ability to increase oil production.

In this first example, a surfactant EOR treatment is combined with awell treatment for purposes of applying a scale inhibitor chemical intothe reservoir. This second treatment is called commonly a “scaleinhibitor squeeze”. The process for the scale inhibitor squeeze involvesinjection of a solution containing a scale inhibitor chemical, injectingan overflush brine solution to drive the scale inhibitor solutionfurther into the reservoir, allowing for a soak time to permit most ofthe scale inhibitor to be retained within the formation, and thenreturning the production well to normal production. The scale inhibitorthat is inside the reservoir will gradually appear in the producedfluids in a diluted form as the scale inhibitor slowly is leached intothe produced fluids from the formation. The low concentrations of scaleinhibitor in the produced water and oil have the desirable effect ofpreventing the deposition of some water-borne scale deposits in thereservoir and production system over an extended period of time.

Laboratory tests were performed to demonstrate that beneficial effectsto oil recovery can result by from mixing a surfactant EOR system with ascale inhibitor chemical solution. Such a chemical mixture of surfactantand scale inhibitor can occur in-situ in the process disclosed herein.

One test series compared the oil recovery performance for a surfactantEOR solution by itself, and then in the presence of a dissolved scaleinhibitor chemical. The procedure for these two comparison tests was asfollows:

-   -   Two artificial cores (consists of finely disaggregated dolomite        particles packed into a wire-mesh cylinder) were completely        saturated with a light crude oil taken from a carbonate        reservoir located in West Texas.    -   One core was immersed into a solution containing 0.2 wt %        Tergitol 15-S-7 nonionic surfactant. (The composition of the        salt solution containing the treatment chemicals is given in        Table 1 below. This salt solution, with a total dissolved        concentration slightly more than 3 wt %, is similar to that        found in some fractured carbonate reservoirs in West Texas.)    -   The second core was immersed into a solution containing with 0.2        wt % Tergitol 15-S-7 nonionic surfactant, plus 100 pm of a        commercial scale inhibitor, Dequest 2066.    -   Each core was placed in a separate Amott cell. The Amott cell        device includes a volumetric burette attached to the top of a        vessel to collect all of the crude oil expelled and recovered        from the artificial core.    -   The cumulative volume of crude oil expelled and collected from        each core was measured, versus the soaking time.

TABLE 1 Recipe for Salt Solution Used as Diluent for the Surfactant andthe Surfactant Plus Scale Inhibitor Solutions Salt Amount added to 1liter of distilled water NaCl 20.0 grams NaSO4 2.95 grams CaCl2•2H2O 4.4 grams MgCl2•6H2O 3.35 grams

Table 2 (below) compares the oil recovery performance in a laboratorytest with one sample having a surfactant EOR solution by itself versus asecond sample with a chemical solution that also includes a lowconcentration of a common scale inhibitor. The cumulative oil recoverywith the surfactant alone is approximately 59% of the initial oil volumein the artificial core. In contrast, the solution that has the scaleinhibitor combined with the surfactant has a greater oil recovery ofover 66% after soaking for 683 hours. Of importance, note that asolution of the scale inhibitor by itself recovers virtually no oilunder the same experimental conditions.

TABLE 2 Comparison of the Oil Recovery by a Surfactant EOR SolutionAlone Versus One that Also Has a Scale Inhibitor Percent Oil RecoverySurfactant + Scale Inhibitor 0.2 wt % Tergitol Time Elapsed Surfactant15-S-7 + 200 ppm (Hours) 0.2 wt % Tergitol 15-S-7 Dequest 2066 110 42.840.7 189 50.6 55.6 350 57.1 61.0 693 58.4 66.5

The above experimental results demonstrate there is an unexpectedbeneficial synergistic result of increased oil recovery beyond that ofthe surfactant EOR solution alone, when the treatment solution alsoincludes a scale inhibitor chemical. Hence, the process disclosedherein, i.e., of creating in-situ mixtures of the two types of chemicalsdescribed in the example above, have a benefit of recovering more oilthan otherwise possible by use of the treatments separately.

Example 2

When an EOR surfactant solution is mixed with a scale inhibitorsolution, the capability to prevent a scale precipitate is no worse thanby the scale inhibitor solution alone. That is, the EOR surfactant hasno significant effect on the scale inhibitor treatment process result.

Additional laboratory tests were performed to demonstrate that an EORsurfactant can be mixed into a scale inhibitor chemical solution and notadversely impact the scale inhibitor performance. Such a chemicalmixture of surfactant and scale inhibitor can occur in-situ inaccordance with the presently disclosed processes, wherein a surfactantEOR treatment is combined with a scale inhibitor squeeze.

A series of laboratory tests were performed to compare the ability of ascale inhibitor only, versus a mixture of a scale inhibitor and asurfactant EOR solution to inhibit successfully the formation ofwater-borne scale deposits. The surfactants selected were two commercialnonionic products, Neodol 25-9 and Igepal CO-630, suitable for thesurfactant process of this invention. The scale inhibitor selected was acommercial product called Dequest 2066.

The test procedure for this series of tests was as follows:

-   -   Make a solution using the mixture of salts as described in        Table 1. Call this Brine A.    -   Make a solution of a solution containing 50 grams per liter of        sodium carbonate. Call this Brine B.    -   Create 4 different solutions, and adjust to pH 7

Solution 1 50 grams of Brine A Solution 2 50 grams of Brine A + 100 ppmDequest Solution 3 50 grams of Brine A + 100 ppm Dequest + 0.2 wt %Neodol Solution 4 50 grams of Brine A + 100 ppm Dequest + 0.2 wt %Igepal CO- (Note that all 4 of these mixtures, Solutions 1 through 4initially are clear)

-   -   Create 4 different samples for testing for scale inhibition

Sample 1 Solution 1 + 3 grams of Brine B Sample 2 Solution 2 + 3 gramsof Brine B Sample 3 Solution 3 + 3 grams of Brine B Sample 4 Solution4 + 3 grams of Brine B

-   -   Place all 4 samples in an oven at 40 degrees Centigrade    -   Observe the clarity of the different samples and record the        appearance of each solution versus elapsed time.

It is expected that mixing the salt solution Brine A with the sodiumbicarbonate solution Brine B will induce the inorganic water-borneprecipitate calcium carbonate. Furthermore, this process is expected tobe even worse if the final solution is heated above room temperaturebecause calcium carbonate is well known to be less soluble at elevatedtemperatures.

The results are summarized as follows in Table 3 below.

TABLE 3 Summary of Scale Inhibition Results - Clarity of Brine SolutionsAged at 40 C. Time Elapsed (min) Solution 1 Solution 2 Solution 3Solution 4 0 clear clear clear clear 15 cloudy clear clear clear 30cloudy clear clear clear 60 visible solids cloudy cloudy cloudy

These results show that, as expected, Solution 1 (with no scaleinhibitor) was the first to exhibit signs of incompatibility, with acloudy appearance before 15 minutes, and visible suspended solidsobserved within 1 hour. The other 3 solutions (two of which contain somesurfactant) all maintained a clear appearance for 30 minutes, and somecloudiness at 60 minutes. This indicates the Dequest 2066 was performingas a scale inhibitor, and that the presence of either of the twosurfactants (in Solutions 3 and 4) did not hinder the ability of theadded scale inhibitor to delay the onset of solids formation.

Example 3

A surfactant suitable for the EOR process in according to the presentdisclosure is compatible with an acid solution used in wellstimulations.

Hydrochloric acid solutions are used frequently in well stimulationtreatments of oil and gas production wells. There often are employed todissolve bothersome scale deposits, such as calcium carbonate. One issuerelevant to the present disclosure is if the surfactant process iscombined with the usual acid treatment solution, will this mixture becompatible?

To that end, we compared the solution appearance of the following atroom temperature:

-   -   Brine A in Example 2    -   Brine A in Example 2+1 wt % HCl    -   Brine A in Example 2+1 wt % HCl+0.2 wt % Igepal CO-630

All of these solutions remained clear throughout the 20 days ofobservation. Thus, this example illustrates that a compatible mixturethat is a stable brine solution containing hydrochloric acid and also asurfactant suitable for the improved oil recovery processes describedherein is feasible.

Example 4

A surfactant suitable for the EOR process described herein added to anacid treatment solution will recover more oil than either individualprocess.

The test procedure was the same as shown above in Example 1, except forthe choice of the test solutions. These include:

(a) Surfactant only—0.2 wt % Igepal CO-630—a commercial nonionicsurfactant

(b) Surfactant plus acid—0.2 wt % Igepal CO-630+0.25 wt % HCl

(c) Acid only—0.25 wt % HCl

Each chemical system was added to an Amott cell containing a limestonecore saturated with a West Texas crude oil. The initial oil content ofthe 3 cores was measured to be nearly the same for all of them:

(a) 5.83 gram

(b) 6.19 gram

(c) 6.26 gram

After immersing the cores with the respective test solutions in theirindividual Amott cells, the oil recovery was measured versus time. Theresults are as follows:

TABLE 4 Comparison of Oil Recovery by Chemical Soaking of a LimestoneCore Containing a West Texas Crude Oil. Oil Recovery (ml) Elapsed TimeSystem a System b System c  2 hours 0.1 0.1 0.1 16 hours 0.2 1.7 0.9 24hours 2.2 3.3 2.4

As can be seen, the oil recovery is better with a combined surfactantplus acid solution than either one alone.

This demonstrates the non-obvious result that the oil recovery issurprisingly greater for the combination of surfactant and acid thaneither individual solution. These results show that the surfactant andacid work better together by improved penetration of the aqueous fluidthat has a feature a dissolving effect on the porous matrix. This alsodemonstrates that an acid solution combined with a surfactant solutionwill recover oil effectively if such a solution is injected into aninjection well.

A further embodiment includes providing a surfactant solution and anon-surfactant solution (or “second solution”) to a carbonateoil-bearing reservoir in concert with one another, and within aproximate temporal period to one another. The proximate temporal periodis less than the time period traditionally employed when using thesurfactant solution and the second solution individually. That is,traditionally a surfactant solution and a non-surfactant solution areprovided to a reservoir at different times, with the time period betweenapplications of the two solutions being more than six months. I havedetermined that, by applying a surfactant solution and a non-surfactantsolution together within a temporal period that is less than thetraditional period, greater oil recovery can be obtained from acarbonate reservoir than if the two solutions are applied at thetraditional times. Advantageously, I have determined that additional oilrecovery can be obtained if the surfactant solution and thenon-surfactant solution are applied within less than six months of oneanother, and more advantageously if the proximate temporal period isabout thirty days. In either case, it will be appreciated that thedisclosed proximate temporal period between applying the surfactantsolution and the non-surfactant solution is significantly less than thetraditional temporal period employed for providing these solutions to acarbonate reservoir individually. It will be further appreciated thatthe “proximate temporal period” for applying the surfactant solution andthe second solution can also include applying these two solutionssimultaneously.

Further, I have discovered that increased oil production from afractured carbonate reservoir can be achieved by combining a surfactantsolution and a non-surfactant solution to the reservoir within aproximate temporal period to one another (as described above), andwherein the non-surfactant solution is a well-servicing volumetricsolution. A “well-servicing volumetric solution” is a solutionconfigured to increase the volume of fluids that can be produced from awell in communication with the carbonate reservoir, and is not intendedto increase the production of oil over other fluids in the reservoir.That is, a “well-servicing volumetric solution” only enables highervolumes of fluids to be produced from the well, without regard towhether the fluids contain additional oil or not. For example, a scaleinhibitor is one kind of “well-servicing volumetric solution”, and isconfigured to remove scale from production piping and the like to enableincreased volumetric flow of fluids from the reservoir through the well(or wellbore). However, it will be fully appreciated by those of skillin the art that a scale inhibitor has no effect on the oil-to-water (or“oil-to-any-other-reservoir-fluid”) ratio, but merely allows increasedvolumes of fluids to be produced from the reservoir. Other“well-servicing volumetric solutions” include acidizing or fracturing awell. Put another way, I have discovered that, by combining a surfactantsolution to an oil-bearing carbonate reservoir (with the previouslyexpected increase in oil-to-water increase in production as a resultthereof), along with a “well-servicing volumetric solution” (asdescribed above), that greater oil recovery can be achieved from thereservoir than if these two solutions are provided to the reservoir inthe traditional manner (i.e., using the traditional temporal separationof the two solutions).

In a further embodiment, I have determined that increased oil recoveryfrom a fractured carbonate oil-bearing reservoir can be obtained byinjecting, into the reservoir, and within a proximate temporal period ofone another, a surfactant solution and a weak acid solution. (Examplesof a “weak acid” include, but are not limited to, carbon dioxide, aceticacid, formic acid, and (weak) hydrochloric acid.)

Those skilled in the art will recognize that modifications andvariations can be made to the above disclosure without departing fromthe spirit of the present disclosure. Therefore, it is intended thatthis disclosure encompass all such variations and modifications as fallwithin the scope of the current disclosure, and the appended claims.Further, it is intended that the appended claims do not limit the scopeof the above disclosure, and can be amended to include features herebyprovided for within the present disclosure.

1. A method to enhance oil recovery from a fractured carbonatereservoir, the reservoir being accessible via a production well, themethod comprising: injecting a surfactant solution comprisingsurfactants into the production well, the surfactant solution selectedto recover additional oil from a porous matrix portion of the reservoir;and injecting a second well treatment process, comprising a second welltreatment solution, into the production well; and wherein: the secondwell treatment solution is selected from the group consisting of a scaleinhibition squeeze process, a well acidizing process, a chemical processto reduce water production rate, an acid fracturing process, and ahydraulic fracturing process; and the surfactant solution and the secondwell treatment solution are injected into the production well withinless than about six months of one another.
 2. The method of claim 1, andwherein the surfactant solution and the second well treatment solutionare injected into the production well within less than about thirty daysof one another.
 3. The method of claim 1, and further comprising: (a)halting fluid production from the production well; (b) injecting a slugof the surfactant solution; (c) shutting in the production well for afirst soaking period of time; (d) injecting fluids associated with thesecond well treatment process into the production well; (e) shutting inthe well production for a second soaking period of time; and (f)returning the production well to fluid production to recover additionaloil from the reservoir.
 4. The method of claim 3, and furthercomprising, between steps (b) and (d), injecting a spacer slug of inertfluid into the production well.
 5. The method of claim 1, and furthercomprising: (a) halting fluid production from the production well; (b)injecting fluids associated with the second well treatment process intothe production well; (c) injecting a slug of the surfactant solution;(d) injecting a spacer slug of inert fluid into the production well; (e)shutting in the production well for a soaking period of time; and (f)returning the production well to fluid production to recover additionaloil from the reservoir.
 6. The method of claim 5, and furthercomprising, between steps (b) and (d), injecting a spacer slug of inertfluid into the production well.
 7. The method of claim 1, furthercomprising: (a) halting fluid production from the production well; (b)simultaneously injecting the second well treatment solution and thesurfactant solution into the production well; (c) shutting in the wellfor a soaking period of time; and (d) returning the production well toproduction to recover additional oil from the reservoir.
 8. The methodof claim 7, further comprising, between steps (b) and (c), injecting aspacer slug of inert fluid into the production well.
 9. The method ofclaim 1, wherein the surfactant is defined by properties comprising atleast one of the following features: (a) the ability to change a wettingof the porous matrix rock to prefer wetting by an aqueous phase; (b) theability to lower an oil and water interfacial tension between oil andwater in the reservoir; or (c) to enhance compatibility with chemicalsin the second well treatment process.
 10. The method of claim 1 andwherein the surfactant solution is selected from the group consisting ofethoxylated alkylphenols, ethoxysulfate alkylphenols, ethoxylatedalcohols, ethoxysulfate alcohols, alpha olefin sulfonates, internalolefin sulfonates, alkyl aryl sulfonates, petroleum sulfonates,propoxylated ethoxylated alcohols, propoxylated ethoxylated sulfates,propoxylated ethoxylated sulfonates, amine salts, ammonium salts, andmixtures thereof, including primary amines.
 11. The method of claim 1and wherein the surfactant solution is manufactured from biosynthesis(biosurfactant), including rhamnolipd and surfactin types thereof. 12.The method of claim 11, and wherein the surfactant solution comprisessurfactants manufactured from biosynthesis (biosurfactant), includingrhamnolipd and surfactin types thereof.
 13. The method of 1, furthercomprising injecting a spacer slug into the reservoir in sequence withthe surfactant solution and the second well treatment solution, andwherein the spacer slug is selected from the group consisting of freshwater brine, and a hydrocarbon.
 14. The method of claim 1, and whereinthe second well treatment solution contains at least one of a portion ofthe surfactant solution, or a second surfactant selected to recoveradditional oil from the porous matrix portion of the reservoir.
 15. Amethod comprising injecting a surfactant and acid mixture into afractured carbonate reservoir for enhance oil recovery.
 16. The methodof claim 15, and wherein the acid is selected from the group consistingof hydrochloric acid, acetic acid, carbon dioxide, and sulfuric acid.